Wellbores for the oil and gas industry are commonly drilled by a process of rotary drilling. In conventional wellbore drilling, a drill bit is mounted on the end of a drill string, which may be several miles long. At the surface of the wellbore, a rotary drive or top drive turns the drill string, including the drill bit arranged at the bottom of the hole to increasingly penetrate the subterranean formation, while drilling fluid is pumped through the drill string to remove cuttings. In other drilling configurations, the drill bit may be rotated using a downhole mud motor arranged axially adjacent the drill bit and powered using the circulating drilling fluid.
One common type of drill bit used to drill wellbores is known as a “fixed cutter” or a “drag” bit. This type of drill bit has a bit body formed from a high strength material, such as tungsten carbide or steel, or a composite/matrix bit body, having a plurality of cutters (also referred to as cutter elements, cutting elements, or inserts) attached at selected locations about the bit body. The cutters may include a substrate or support stud made of carbide (e.g., tungsten carbide), and an ultra-hard cutting surface layer or “table” made of a polycrystalline diamond material or a polycrystalline boron nitride material deposited onto or otherwise bonded to the substrate. Such cutters are commonly referred to as polycrystalline diamond compact (“PDC”) cutters.
In fixed cutter drill bits, PDC cutters are rigidly secured to the bit body, such as being brazed within corresponding cutter pockets defined on blades extending from the bit body. The PDC cutters may be positioned along the leading edges of the blades of the bit body so that the PDC cutters engage the formation during drilling. In use, high forces are exerted on the PDC cutters, particularly in the forward-to-rear direction. Over time, the portion of each cutter that continuously contacts the formation, referred to as the working surface or cutting edge, eventually wears down and/or fails.